The World's First Offshore GASWAG EOR Full Field Implementation

2021 ◽  
Author(s):  
Ahmad Khanifar ◽  
Ibrahim Bin Subari ◽  
Mohd Razib Bin Abd Raub ◽  
Raj Deo Tewari ◽  
Mohd Faizal Bin Sedaralit
Keyword(s):  
Oil Recovery ◽  
Success Factors ◽  
Water Injection ◽  
Dynamic Modelling ◽  
Base Case ◽  
Well Testing ◽  
Actual Performance ◽  
Full Field ◽  
Good Communication ◽  
Water Alternating Gas

Abstract A major matured Malaysian offshore oilfield with more than 40 years of production history under a combination of moderate to strong aquifer support and moderate-size gas cap will be subjected to a unique enhanced oil recovery (EOR) scheme, the first of its kind offshore, called Gravity Assisted Simultaneous Water Alternating Gas (GASWAG) injection process. It is essentially a scheme which involves simultaneously injection of gas and water which involves injecting water up-dip and gas down-dip structurally in a depleted oil reservoir. This method takes the advantage of gravity drainage mechanism to maximize recovery from un-swept oil zones down-dip by aquifer influx and up-dip by gas cap expansion processes and it could be different than the conventional water alternating gas (WAG) method. This paper mostly presents the dynamic modelling and simulation work which has been established during this case study to obtain the GASWAG base case model and to conduct the optimization and sensitivity assessments on the major reservoir parameters. It also describes the main subsurface uncertainties and operational risks and their impact on incremental oil reserve and the results were used to design mitigation plans to help minimize impact on oil recovery volumes. Implementing the full field scale of this EOR scheme involves a detailed reservoir management plan (RMP) with many reactivations of idle wells, well workover plans, behind casing opportunities and adding perforation interval together with identified new infill wells to maximize the flood-front movement of the injected fluids. Obviously, good communication with field operational personnel is paramount to ensure these RMP are adhered to clear targets to successfully achieve the desired incremental recovery and will be elaborated in this paper. This paper describes the strategy and workflow to monitor and measure the two key success factors of this project which are production attainability and reserve attainability. The success of this project depends on continuous evaluation to check the actual performance against the anticipated behavior. As soon as new information obtains along implementation, it will be assessed against targets to steer the way to the main goal of additional reserve by the end of field life. Thus, it requires a comprehensive monitoring plan with detailed surveillance and data collection and, well testing to revisit and update the dynamic model accordingly. The results of this study show that GASWAG has emerged to be one of the most promising techniques with the highest incremental reserve for this field among various EOR techniques evaluated such as continuous gas injection, continuous water injection, conventional WAG, aquifer-assisted WAG, and double displacement.

scholarly journals The effect of chemically enhanced oil recovery on thin oil rim reservoirs

2021 ◽  
Vol 11 (3) ◽  
pp. 1461-1474
Author(s):  
O. A. Olabode ◽  
V. O. Ogbebor ◽  
E. O. Onyeka ◽  
B. C. Felix
Keyword(s):  
Enhanced Oil Recovery ◽  
Oil Recovery ◽  
Niger Delta ◽  
Surfactant Concentration ◽  
Base Case ◽  
Production Studies ◽  
Water Alternating Gas ◽  
Water Coning ◽  
Oil Rim

AbstractOil rim reservoirs are characterised with a small thickness relative to their overlying gas caps and underlying aquifers and the development these reservoirs are planned very carefully in order to avoid gas and water coning and maximise oil production. Studies have shown low oil recoveries from water and gas injection, and while foam and water alternating gas injections resulted in positive recoveries, it is viewed that an option of an application of chemical enhanced oil recovery option would be preferable. This paper focuses on the application of chemical enhanced oil recovery to improve production from an oil rim reservoir in Niger Delta. Using Eclipse black oil simulator, the effects of surfactant concentration and injection time and surfactant alternating gas are studied on overall oil recovery. Surfactant injections at start and middle of production resulted in a 3.7 MMstb and 3.6 MMstb at surfactant concentration of 1% vol, respectively. This amounted to a 6.6% and 6.5% increment over the base case of no injection. A case study of surfactant alternating gas at the middle of production gave an oil recovery estimate of 10.7%.

Instow: A Full-Field, Multipatterned Alkaline-Surfactant-Polymer Flood—Analyses and Comparison of Phases 1 and 2

2021 ◽  
pp. 1-15
Author(s):  
M. J. Pitts ◽  
E. Dean ◽  
K. Wyatt ◽  
E. Skeans ◽  
D. Deo ◽  
...  
Keyword(s):  
Oil Recovery ◽  
Phase 1 ◽  
Water Injection ◽  
Phase 2 ◽  
Full Field ◽  
Two Phases ◽  
Original Oil In Place ◽  
Total Oil ◽  
Operation Cost ◽  
Alkaline Surfactant Polymer

Summary An alkaline-surfactant-polymer (ASP) project in the Instow field, Upper Shaunavon Formation in Saskatchewan, Canada, was planned in three phases. The first two multiwell pattern phases are nearing completion. Beginning in 2007, an ASP solution was injected into Phase 1. Phase 1 polymer drive injection began in 2011 after injection of 37% pore volume (PV) ASP solution. Coincident with the polymer drive injection into Phase 1, Phase 2 ASP solution injection began. Phase 2 polymer drive began in 2016 after injection of 55% PV ASP solution. Polymer solution injection for the polymer drives of both phases continues in both phases with Phase 1 and Phase 2 injected volumes being 55 and 42% PV as of August 2019, respectively. Phase 1 and Phase 2 oil cut response to ASP injection showed an increase of approximately four times from 3.2% to a peak of 13.0% for Phase 1 and Phase 2 oil cut increased from 1.8% to a peak of 14.8%, approximately eightfold. Oil rates increased from approximately 3200 m3/m (20 127 bbl/m) at the end of water injection to a peak of 8300 m3/m (52 220 bbl/m) in Phase 1 and from 1230 m3/m (7 736 bbl/m) to 6332 m3/m (39 827 bbl/m) in Phase 2. Phase 1 pattern analysis indicates that the PV of ASP solution injected varied from 13% to 54% PV of ASP. Oil recoveries after the start of ASP solution injection in the different patterns ranged from 2.3% original oil in place (OOIP) up to 21.3% OOIP with lower oil recoveries generally correlating with lower volumes of ASP solution injected. Wells in common to the two phases of the project show increased oil cut and oil rate responses to chemical injection from both Phases 1 and 2. Total oil recovery as of August 2019 is 60% OOIP for Phase 1 and 62% OOIP for Phase 2. Phase 1 economic analysis indicated chemical and operation cost was approximately CAD 26/bbl, resulting in the decision to move forward with Phase 2.

The Use of Tracer Data To Determine Polymer-Flooding Effects in a Heterogeneous Reservoir, 8 Torton Horizon Reservoir, Matzen Field, Austria

2016 ◽  
Vol 19 (04) ◽  
pp. 655-663 ◽  
Author(s):  
Torsten Clemens ◽  
Markus Lüftenegger ◽  
Ajana Laoroongroj ◽  
Rainer Kadnar ◽  
Christoph Puls
Keyword(s):  
Oil Recovery ◽  
Water Injection ◽  
Flow Path ◽  
Injection Well ◽  
Critical Parameters ◽  
Pilot Projects ◽  
Sweep Efficiency ◽  
Full Field ◽  
Polymer Injection ◽  
Production Wells

Summary Polymer-injection pilot projects aim at reducing the uncertainty and risk of full-field polymer-flood implementation. The interpretation of polymer-pilot projects is challenging because of the complexity of the process and fluids moving out of the polymer-pilot area. The interpretation is increasingly more complicated with the heterogeneity of the reservoir. In the polymer pilot performed in the 8 Torton Horizon (TH) reservoir of the Matzen field in Austria, a polymer-injection well surrounded by a number of production wells was selected. A tracer was injected 1 week before polymer injection. The tracer showed that the flow field in the reservoir was dramatically modified with increasing amounts of polymer injected. Despite short breakthrough times of 4 to 10 weeks observed for the tracer, polymer breakthrough occurred only after more than 12 months although injection and production rates were not substantially changed. The tracer signal indicated that the reservoir is heterogeneous, with high flow velocities occurring along a number of flow paths with a limited volume that are strongly connecting the injection and production wells. By injecting polymers, the mobility of the polymer-augmented water was reduced compared with water injection, and led to flow diversion into adjacent layers. The tracer response showed that the speed of the tracer moving from injection to production wells was reduced with increasing amount of polymer injected. This response was used to assess the changes of the amount of water flowing from the injection well to production wells. After a match for the tracer curve was obtained, adsorption, residual resistance factor (RRF), and dispersivity were calculated. The results showed that, even for heterogeneous reservoirs without good conformance of the pilot, the critical parameters for polymer-injection projects can be assessed by analyzing tracer and polymer response. These parameters are required to determine whether implementation of polymer injection at field scale is economically attractive. Along the flow path that is connecting injection and production well, as shown by the tracer response, an incremental recovery of approximately 8% was achieved. The polymer retention and inaccessible pore volume (IPV) in the reservoir were in the same range as in corefloods. Incremental oil recovery caused by acceleration along the flow path was estimated at approximately 20% of the overall incremental oil production caused by polymer injection and 80% was attributed to improved sweep efficiency.

Experimental Investigation of Near-Miscible Water-Alternating-Gas Injection Performance in Water-Wet and Mixed-Wet Systems

SPE Journal ◽  
2013 ◽  
Vol 18 (01) ◽  
pp. 114-123 ◽  
Author(s):  
S. Mobeen Fatemi ◽  
Mehran Sohrabi
Keyword(s):  
Relative Permeability ◽  
Oil Recovery ◽  
Gas Injection ◽  
Water Injection ◽  
Laboratory Data ◽  
Co2 Injection ◽  
Water Alternating Gas ◽  
Three Phase ◽  
The Impact ◽  
Wag Injection

Summary Laboratory data on water-alternating-gas (WAG) injection for non-water-wet systems are very limited, especially for near-miscible (very low IFT) gas/oil systems, which represent injection scenarios involving high-pressure hydrocarbon gas or CO2 injection. Simulation of these processes requires three-phase relative permeability (kr) data. Most of the existing three-phase relative permeability correlations have been developed for water-wet conditions. However, a majority of oil reservoirs are believed to be mixed-wet and, hence, prediction of the performance of WAG injection in these reservoirs is associated with significant uncertainties. Reliable simulation of WAG injection, therefore, requires improved relative permeability and hysteresis models validated by reliable measured data. In this paper, we report the results of a comprehensive series of coreflood experiments carried out in a core under natural water-wet conditions. These included water injection, gas injection, and also WAG injection. Then, to investigate the impact of wettability on the performance of these injection strategies, the wettability of the same core was changed to mixed-wet (by aging the core in an appropriate crude oil) and a similar set of experiments were performed in the mixed-wet core. WAG experiments under both wettability conditions started with water injection (I) followed by gas injection (D), and this cyclic injection of water and gas was repeated (IDIDID). The results show that in both the water-wet and mixed-wet cores, WAG injection performs better than water injection or gas injection alone. Changing the rock wettability from water-wet to mixed-wet significantly improves the performance of water injection. Under both wettability conditions (water-wet and mixed-wet), the breakthrough (BT) of the gas during gas injection happens sooner than the BT of water in water injection. Ultimate oil recovery by gas injection is considerably higher than that obtained by water injection in the water-wet system, while in the mixed-wet system, gas injection recovers considerably less oil.

scholarly journals Simulation of Immiscible Water-Alternating-CO2 Flooding in the Liuhua Oilfield Offshore Guangdong, China

Energies ◽  
2020 ◽  
Vol 13 (9) ◽  
pp. 2130 ◽  
Author(s):  
Gang Hu ◽  
Pengchun Li ◽  
Linzi Yi ◽  
Zhongxian Zhao ◽  
Xuanhua Tian ◽  
...  
Keyword(s):  
Oil Recovery ◽  
Carbon Capture ◽  
Co2 Storage ◽  
Simulation Models ◽  
Co2 Injection ◽  
Co2 Flooding ◽  
Full Field ◽  
Water Alternating Gas ◽  
Production History ◽  
And Storage

In this paper, the immiscible water-alternating-CO2 flooding process at the LH11-1 oilfield, offshore Guangdong Province, was firstly evaluated using full-field reservoir simulation models. Based on a 3D geological model and oil production history, 16 scenarios of water-alternating-CO2 injection operations with different water alternating gas (WAG) ratios and slug sizes, as well as continuous CO2 injection (Con-CO2) and primary depletion production (No-CO2) scenarios, have been simulated spanning 20 years. The results represent a significant improvement in oil recovery by CO2 WAG over both Con-CO2 and No-CO2 scenarios. The WAG ratio and slug size of water affect the efficiency of oil recovery and CO2 injection. The optimum operations are those with WAG ratios lower than 1:2, which have the higher ultimate oil recovery factor of 24%. Although WAG reduced the CO2 injection volume, the CO2 storage efficiency is still high, more than 84% of the injected CO2 was sequestered in the reservoir. Results indicate that the immiscible water-alternating-CO2 processes can be optimized to improve significantly the performance of pressure maintenance and oil recovery in offshore reef heavy-oil reservoirs significantly. The simulation results suggest that the LH11-1 field is a good candidate site for immiscible CO2 enhanced oil recovery and storage for the Guangdong carbon capture, utilization and storage (GDCCUS) project.

Investigation of Significance of Critical Components in Optimization of WAG Injection Processes under Uncertainty

2014 ◽  
Author(s):  
C.. Temizel ◽  
S.. Purwar ◽  
A.. Agarwal ◽  
A.. Abdullayev ◽  
K.. Urrutia ◽  
...  
Keyword(s):  
Oil Recovery ◽  
Large Fraction ◽  
Water Injection ◽  
Sweep Efficiency ◽  
Improved Oil Recovery ◽  
Injection Process ◽  
Water Alternating Gas ◽  
Gas Flooding ◽  
Reservoir Simulator ◽  
Wag Injection

Abstract Water alternating gas (WAG) injection has been widely used for the last 50 years throughout the world. The typical improved oil recovery (IOR) potential for WAG injection compared with water injection is 5 to 10%. It was originally intended to improve sweep efficiency during gas flooding, with intermittent slugs of water and gas designed to follow the same route through the reservoir. Mechanisms in WAG injection include microscopic effects, particularly in cases where three-phase flow and hysteresis are important for the IOR effect. Injection of gas usually aids an ongoing waterflood, and finding technical and commercial methods to reduce gas costs would be useful. Water injection alone tends to sweep the lower parts of a reservoir, while gas injected alone sweeps more of the upper parts of a reservoir because of gravitational forces. Gas represents a large fraction of the total cost, making WAG injection an expensive method. Thus, optimizing WAG injection is not only crucial in terms of recovery but also economics, especially where gas is expensive and/or limited. In this study, the significance of key components in a WAG injection process on SPE's 5th Comparative Solution Project (CSP) is presented that models the WAG process through a pseudo-miscible formulation by means of coupling a full-physics reservoir simulator with commercial optimization and uncertainty software. The results are analyzed and presented in a comparative manner by means of tornado charts showing the significance of each decision and uncertainty variable.

scholarly journals Modeling of CO2-LPG WAG with asphaltene deposition to predict coupled enhanced oil recovery and storage performance

2021 ◽  
Vol 11 (1) ◽  
Author(s):  
Jinhyung Cho ◽  
Baehyun Min ◽  
Moon Sik Jeong ◽  
Young Woo Lee ◽  
Kun Sang Lee
Keyword(s):  
Enhanced Oil Recovery ◽  
Oil Recovery ◽  
Carbon Capture ◽  
Water Injection ◽  
Carbon Capture And Storage ◽  
Liquefied Petroleum Gas ◽  
Water Alternating Gas ◽  
Asphaltene Deposition ◽  
Trapping Performance ◽  
And Storage

AbstractCombined carbon capture and storage and CO2-enhanced oil recovery (CCS-EOR) can reconcile the demands of business with the need to mitigate the effects of climate change. To improve the performance of CCS-EOR, liquefied petroleum gas (LPG) can be co-injected with CO2, leading to a reduction in the minimum miscibility pressure. However, gas injection can cause asphaltene problems, which undermines EOR and CCS performances simultaneously. Here, we systematically examine the mechanisms of asphaltene deposition using compositional simulations during CO2-LPG–comprehensive water–alternating-gas (WAG) injection. The LPG accelerates asphaltene deposition, reducing gas mobility, and increases the performance of residual trapping by 9.2% compared with CO2 WAG. In contrast, solubility trapping performance declines by only 3.7% because of the greater reservoir pressure caused by the increased formation damage. Adding LPG enhances oil recovery by 11% and improves total CCS performance by 9.1% compared with CO2 WAG. Based on reservoir simulations performed with different LPG concentrations and WAG ratios, we confirmed that the performance improvement of CCS-EOR associated with increasing LPG and water injection reaches a plateau. An economic evaluation based on the price of LPG should be carried out to ensure practical success.

An Australian first initiative to re-develop the first commercial onshore oilfield into a CO2 miscible-EOR project

2019 ◽  
Vol 59 (1) ◽  
pp. 179
Author(s):  
Stephanie Barakat ◽  
Bob Cook ◽  
Karine D'Amore ◽  
Alberto Diaz ◽  
Andres Bracho
Keyword(s):  
Oil Recovery ◽  
Dynamic Modelling ◽  
Oil Production ◽  
Simulation Modelling ◽  
Oil Field ◽  
Optimal Time ◽  
Successful Implementation ◽  
Full Field ◽  
Execution Phase ◽  
Reservoir Simulator

The Moonie onshore oil field discovered in 1961, was the first commercial oil discovery in Australia. The field was purchased by Bridgeport Energy Limited (BEL) from Santos in late 2015. An Australian first initiative by BEL is to enhance oil production from the field using tertiary recovery CO2 miscible flood to maximise field oil recovery. The process involves an evaluation of well injection strategies for a miscible displacement process using reservoir simulation modelling. In addition, the project jointly addresses community concerns regarding the rise in greenhouse gas emissions by sourcing 60000–120000 tonnes/annum of CO2 from a nearby power station and/or an ethanol plant. Justified by laboratory experiments and reservoir compositional simulations, BEL’s project timeline to implement a CO2-enhanced oil recovery (EOR) pilot could start from 2020 followed by a 2–3-year full field oil production acceleration project if additional CO2 can be sourced. Based on incremental recovery and operational consideration, an injection well in the southern end of the field surrounded by six existing producers has been selected as a pilot flood. Positive indicative economics are achieved by the efficient displacement with CO2 of 8000 scf/bbl of incremental oil. Full field dynamic modelling predicts a further 8% oil recovery factor by injecting 60 Bcf of CO2 over five years, which could store in excess of three million tonnes of CO2. For the pilot, more than 90% of the injected CO2 will remain in the Precipice sandstone reservoir. However, the efficiency and viability of a CO2-EOR project is subject to successful implementation of the miscibility modelling, logistics and injection strategy and uncertainty quantification. To propel the project into the execution phase a fast-multiphase reservoir simulator has been implemented to complete a probabilistic range of results in optimal time.

Simulation of Scale Inhibitor Squeeze Treatments in a Polymer Flooded Reservoir

2021 ◽  
Author(s):  
Alan Beteta ◽  
Oscar Vazquez ◽  
Munther Mohammed Al Kalbani ◽  
Faith Eze
Keyword(s):  
Oil Recovery ◽  
Reservoir Simulation ◽  
Water Injection ◽  
High Viscosity ◽  
Polymer Flooding ◽  
Base Case ◽  
Scale Inhibitor ◽  
Polymer Flood ◽  
Water Rate ◽  
The Impact

Abstract This study aims to demonstrate the changes to scale inhibitor squeeze lifetimes in a polymer flooded reservoir versus a water flooded reservoir. A squeeze campaign was designed for the base water flood system, then injection was switched to polymer flooding at early and late field life. The squeeze design strategy was adapted to maintain full scale protection under the new system. During the field life, the production of water is a constant challenge. Both in terms of water handling, but also the associated risk of mineral scale deposition. Squeeze treatment is a common technique, where a scale inhibitor is injected to prevent the formation of scale. The squeeze lifetime is dictated by the adsorption/desorption properties of the inhibitor chemical, along with the water rate at the production well. The impact on the adsorption properties and changes to water rate on squeeze lifetime during polymer flooding are studied using reservoir simulation. A two-dimensional 5-spot model was used in this study, considered a reasonable representation of a field scenario, where it was observed that when applying polymer (HPAM) flooding, with either a constant viscosity or with polymer degradation, the number of squeeze treatments was significantly reduced as compared to the water flood case. This is due to the significant delay in water production induced by the polymer flood. When the polymer flood was initiated later in field life, 0.5PV (reservoir pore volumes) of water injection, water cut approximately 70%, the number of squeeze treatments required was still lower than the water flood base case. However, it was also observed that in all cases, at later stages of field life the positive impacts of polymer flooding on squeeze lifetime begin to diminish, due in part to the high viscosity fluid now present in the production near-wellbore region. This study represents the first coupled reservoir simulation/squeeze treatment design for a polymer flooded reservoir. It has been demonstrated that in over the course of a field lifetime, polymer flooding will in fact reduce the number of squeeze treatments required even with a potential reduction in inhibitor adsorption. This highlights an opportunity for further optimization and a key benefit of polymer flooding in terms of scale management, aside from the enhanced oil recovery.

scholarly journals Evaluation of reservoir performance by waterflooding: case based on Lanea oilfield, Chad

2021 ◽  
Vol 11 (3) ◽  
pp. 1339-1352
Author(s):  
Mahamat Tahir Abdramane Mahamat Zene ◽  
Nurul Hasan ◽  
Ruizhong Jiang ◽  
Guan Zhenliang ◽  
Nurafiqah Abdullah
Keyword(s):  
Oil Recovery ◽  
Water Injection ◽  
Oil Field ◽  
Base Case ◽  
Reservoir Pressure ◽  
Reservoir Performance ◽  
Production Location ◽  
Left Behind ◽  
Production Behavior

AbstractThe research of the current study is primarily focused on evaluating the reservoir performance by utilizing waterflood technique, based on a case study at Lanea oil field located in Chad; various mechanisms along with approaches were used in considering the best suitable pattern for waterflooding. All the simulation work was compared against a base case, where there was no involvement of water injection. Moreover, for the base case, a significant amount of oil left behind and cannot be swept, because of lower reservoir pressure at the downhill. The recovery factor obtained was in the range of 14.5–15% since 2010, and in order to enhance the oil production, an injection well was applied to boost the reservoir pressure; oil recovery is improved. In addition, sensitivity analysis study was performed to reach the optimum production behavior achieved by possible EOR method. Parameters, such as grid test, injection position, proper selection production location, permeability, and voidage substitution, were defined in the simulation study.

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